The use of alkyl polyglycoside formulations for various cleaning operations in wellbores is well known to those skilled in the art and is disclosed in U.S. Pat. No. 5,977,032 issued Nov. 2, 1999 to Albert F. Chan, U.S. Pat. No. 5,830,831 issued Nov. 3, 1998 to Albert F. Chan and Kieu, T. Ly, U.S. Pat. No. 5,874,386 issued Feb. 23, 1999 to Albert F. Chan, William Mark Bohon, David J. Blumer, and Kieu T. Ly, U.S. Pat. No. 6,000,412 issued Dec. 14, 1999 to Albert F. Chan, William Mark Bohon, David J. Blumer, Kieu T. Ly, and William G. McLelland, U.S. Pat. No. 6,112,814 issued Sep. 5, 2000 to Albert F. Chan, William Mark Bohon, David J. Blumer and Kieu T. Ly, and U.S. Pat. No. 6,090,754 issued Jul. 18, 2000 to Albert F. Chan and Kieu T. Ly. These patents are hereby incorporated in their entirety by reference. Other patents that disclose the use of alkyl polyglycosides are U.S. Pat. No. 4,985,154 issued Jan. 15, 1991 to Dieter Balzer and Harald Lueders and U.S. Pat. No. 5,725,470 issued Mar. 10, 1998 to Virginia L. Lazarowitz, Allen D. Urfer and George A. Smith. These patents are hereby incorporated in their entirety by reference.
The use of an aqueous liquid alkyl polyglycoside formulation for cleaning wellbores and the like has been well known and is disclosed for various applications in the patents referred to above. While such formulations have been effective for removal of contaminants from an annulus between a casing and a wellbore and the like, they have not been used to clean filter cakes, such as drill-in-fluid filter cakes, from horizontal wellbores.
Water-based drill-in-fluids, herein drill-in-fluids, are frequently used in the completion of horizontal wells to produce more easily removable filter cakes on the inside of a wellbore penetrating productive areas of a formation. Typically the primary drilling mud includes materials well known to the art, such as bentonite clays, barite, polymers, such as xanthan gum, starch and the like. These primary drilling fluids produce filter cakes which function to reduce fluid loss from the wellbore during drilling. Drill-in-fluids are substituted for primary drilling fluids for drilling through the productive formation(s) in open-hole horizontal wells. Drill-in-fluids typically contain polymers, such as xanthan gum, starch, sized salt bridging particles, such as sized calcium carbonate or sodium chloride particles. Other materials may be included, but the primary ingredients are as listed above. Different sized inorganic salt particles may be used.
During typical drilling operations for horizontal open-hole well completions, primary drilling muds are used to drill to a depth near the top of a producing formation(s). At this point, the primary drilling mud is switched to a drill-in-fluid that displaces the primary drilling fluid from the wellbore and is thereafter used as a drilling fluid for drilling the wellbore through the producing formation(s). Both the primary drilling mud and the drill-in-fluid create filter cakes on the inside of the wellbore as filtrate from the drilling mud or the drill-in-fluid escape into the formation through the inside diameter of the wellbore. These filter cakes serve to stop the loss of fluids during drilling. Unfortunately the filter cake, once formed, also restricts fluid flow from the formation during production.
The drill-in-fluid produces a filter cake on the inside of the fluid-producing zone, which is designed for easier removal by breaker treatments using acid, oxidizer or enzyme materials. An acid breaker treatment can constitute simply positioning an aqueous inorganic acid, such as hydrochloric acid, or an aqueous organic acid, such as formic acid, in the production zone and maintaining it in place in the production zone for a period of time in order to react with drill-in-fluid filter cake components, although this is rarely achieved in a horizontal well. These filter cake masses, as mentioned previously, include materials such as starch and calcium carbonate particles, which are readily dissolved by aqueous acids. The residual filter cake is then sloughed off the inside of the wellbore or removed from the inside of the wellbore by production.
As the horizontal section of a horizontal well is drilled with drill-in-fluid, a much more extended wellbore portion is drilled in the producing zone. For instance, the horizontal portion of the well may be up to a few thousand feet or longer. As a result, the recirculated drill-in-fluid becomes contaminated with drilled cuttings from the formation. As the drill-in-fluid becomes more contaminated, the filter cake formed becomes more difficult to remove by a breaker treatment, even with a strong acid treatment. This difficulty is a result of the presence of additional acid insoluble formation cuttings or fines from the formation in the drill-in-fluid in addition to the calcium carbonate sized salt, starch and other components of the drill-in-fluid. The presence of the drilled solids also affects the dissolution or removal rate of the filter cake masses, as some can be removed much slower than others due to blockage of access by the drilled solids on the filter cake surfaces. The result of non-uniform dissolution of some filter cake masses will prematurely open the communications with the formation and subsequently induces a total loss of acid treatment fluid. This is most undesirable because the loss of acid treatment fluid will leave a significant portion of the filter cake mass intact on the formation surface which will continue to inhibit the flow of fluid during production.
As the lateral section of the well is drilled, the contamination of the drill-in-fluid by the formation solids increases. Solids control equipment on the surface can help remove some of the drilled solids and mitigate the problem, but it is not a practical solution since smaller drill solids and fines can be very difficult to remove using such solids control equipment. Accordingly, the filter cake formed on the inside near inlet (heel) surfaces of the horizontal wellbore is substantially clean filter cake of drill-in-fluid constituents. However the filter cake may contain substantial quantities of formation solids toward the end (toe) of the horizontal wellbore. As a result, when acid treatment is used by simply placing an aqueous acid in the horizontal portion of the wellbore, the relatively clean drill-in-fluid filter cake at the heel of the horizontal wellbore can be broken up quickly.
Those filter cakes containing quantities of formation fines in increasing percentages along the length of the horizontal wellbore toward its toe result in increasingly slower removal of the filter cake along the length of the horizontal wellbore. As a result, the aqueous acid solution is lost into the formation through the heel of the horizontal wellbore as the filter cake is destroyed and removed faster than the filter cake near the toe. The result is that the filter cake is effectively removed, at least in part, near the heel of the horizontal wellbore but little effect is seen in the extended portions of the horizontal wellbore beyond the near heel portion. The unremoved or unbroken filter cake will inhibit the flow of fluids during production Attempts to remove such filter cakes more uniformly along the length of the horizontal portion of horizontal wellbores have been made using slower-acting breakers, such as enzymes, oxidizing agents and the like, which are considered to break down the starch. While such techniques have been somewhat successful, they are very slow and typically require from 36 to 48 hours or longer to be effective and also may require difficult, special handling at the surface. Accordingly, an improved method for treating horizontal wellbores to remove filter cakes has been sought.